Identification, imaging and monitoring of fluid-saturated underground reservoirs is a very important application of seismic methods. It helps find and contour gas and oil deposits, which are usually attributed to fluid-saturated porous or fractured geological layers. It also has important applications for underground water reservoir imaging, estimation of contamination zones, and monitoring of underground gas storage, as well as for addressing the global issue of CO2 sequestration. The current very high percentage of “dry” drilled industry wells may be substantially lowered if a more accurate imaging method can be found.
It is commonly known and accepted that thin layers in the earth (with thicknesses less than a fraction of a dominant wavelength [λ]) of seismic waves are invisible to imaging using seismic waves. Waves reflected from a bottom and a top of such a layer have opposite signs and nearly equal amplitudes. The result is that such waves almost cancel one another, resulting in the layer being obscured in the seismic data. Typically this means that traditional seismic methods cannot image layers less than 10 meters thick.
The relationship between seismic response and fluid saturation in a reservoir depends on many factors, such as porosity and permeability of the reservoir rocks, viscosity and compressibility of the fluid, reservoir thickness and physical properties of the surrounding medium. (See “Seismic Wave Attenuation,” 1981, Geophysics reprint series, No. 2: SEG, D. H. Jonson and M. N. Toksoz, editors.). But there is some general connection between the character of porous layer saturation and seismic response. In particular, comparing cases of water and gas saturation, phase shifts and energy redistribution between different frequencies are known. (See Goloshubin, G. M. et al., 1996, “Laboratory experiments of seismic monitoring,” 58th EAEG Meeting, Amsterdam, and Goloshubin, G. M., and Bakulin, A. V., 1998, “Seismic reflectivity of a thin porous fluid-saturated layer versus frequency” 68th SEG Meeting, New Orleans, 976–979.]
Experimental studies have shown that intrinsic attenuation is strongly affected by the porous media and fluid saturation. (See Hauge, P. S., 1981, “Measurements of attenuation from vertical seismic profiles” Geophysics, 46, 1548–1558; Raikes, S. A. and White, J. E., 1984, “Measurements of earth attenuation from downhole and surface seismic recording” Geophysical Prospecting, 32, 892–919; “Seismic Wave Attenuation,” 1981, Geophysics reprint series, No. 2: SEG, D. H. Jonson and M. N. Toksoz, editors; Sams, M. S. et al., 1997, “The measurement of velocity dispersion and frequency-dependent intrinsic attenuation in sedimentary rocks,” Geophysics, 62, 1456–1464; Dasgupta, R. and Clarc, R. A, 1998, “Estimation of Q from surface seismic reflection data,” Geophysics, 63, 2120–2128; Goloshubin, G. M. and Korneev, V. A., 2000, “Seismic low frequency effects for fluid-saturated porous media,” Expanded Abstracts, SEG Meeting, Calgary, 976–979.)
It is well accepted that the nondimensional attenuation quality factor Q is frequency-dependent and changes dramatically with liquid saturation and may be less than 10 in sedimentary rocks (See Jones, T. D., 1986, “Pore fluids and frequency-dependent wave propagation in rocks,” Geophysics, 51, 1939–1953, and Sams [above]). Fluid may lower Q in metamorphic rocks (Pujol, J. M. et al., 1998, “Seismic wave attenuation in metamorphic rocks from VSP data recorded in Germany's continental super-deep borehole,” Geophysics, 63, 354–365) down to 14 and in limestone (Gadoret, T. et al., 1998, “Fluid distribution effects on sonic attenuation in partially saturated limestones,” Geophysics, 63, 154–160) from 200 (dry) to 20–40 (water-saturated).
It is also typically accepted in seismology that attenuation quality factor Q usually has values well above 20, which means that it takes more than 20 wavelengths for a wave to propagate before its amplitude is reduced by more than a half of an original value.